In the production of oil and gas, it is desirable to determine the fractions of flow through the wellbore that are attributed to oil, water, and gas. Water production often increases as oil reserves are depleted, or from a water injection program. Multiphase production logging is therefore useful to define the production profile and to determine whether a zone is producing oil or whether it is producing large quantities of water.
Current production logging instrumentation is limited by the presence of these multiphase flow regimes. Current multiphase logging techniques require the use of a capacitance probe, along with a gradiomanometer. A gradiomanometer is used to determine the density of the fluid flowing in the wellbore. It measures differential pressure between two membrane-type pressure sensors spaced apart. When pressure drops due to fluid friction and hole deflection are negligible, the gradiomanometer permits direct calculation of the average density of the fluid between the two sensors. Frictional pressure drop and hole deflection are included in the density calculation when warranted. The tool is particularly suited for locating gas entries and standing fluid levels. When oil and water densities are close, the gradiomanometer becomes inaccurate and cannot resolve the subtle differences. The tool is usually ported to sense pressure external to the instrument, thereby sampling a large cross-sectional area of wellbore fluid. This improves overall reliability of the measurement. Gradiomanometer readings must be corrected for well deviation if the well is not vertical.
A capacitance probe responds to the proportion of fluids (holdup) present. The holdup of a phase is the ratio of the volume of that phase to the total volume. For example, if a wellbore has both oil and water in it, and if additional oil is injected at the bottom, some of the water is displaced by the oil bubbles and the oil-water interface will rise. The oil "holds up" the water. The water holdup is the original volume of water prior to oil injection divided by the new volume of water plus the injected oil volume.
The capacitance probe uses the dielectric properties of a fluid to distinguish water from hydrocarbon (oil or gas). The fluid mixture flows between two differently charged surfaces, and the dielectric property of the fluid mixture impedes or permits electron flow between the surfaces. The electron flow is directly related to capacitance and inversely related to frequency. Gaseous hydrocarbons have a dielectric constant very near 1.0, whereas oil has a value close to 2.0. By contrast, the dielectric constant of water is 80. Hence, a good dielectric contrast exists between water and hydrocarbon. Usually, the capacitance probe is scaled directly in water holdup units. Capacitance probe response is linear up to 40 percent water holdup. After 40 percent water holdup, however, the response is nonlinear with poor resolution. Therefore beyond 40 percent water holdup the tool is qualitative at best. In addition, uncertainty exists, as the nonlinear calibration varies among logging companies.
In practice, determining two and three phase flow fractions (holdups) as well as phase fraction flow rates only works when the flow is well-mixed, or homogeneous (bubble flow). Bubble flow occurs when small and discrete bubbles of a lighter phase fluid (oil or gas) travel upward in the column of a continuous heavy phase fluid (water or oil). The bubbles generally move at a higher velocity than the continuous heavy phase. It is rare, however, to observe bubble flow entirely along a producing wellbore. Consequently, measurement errors occur when bubble flow is presumed but does not exist, and therefore, calculated phase rates are imprecise. Other flow regimes which may exist instead include slug flow, froth or transition flow, and/or mist flow.
U.S. Pat. No. 4,520,666, issued to Coblentz et al. discloses a method and apparatus for determining a well's production profile. The method is only used for single phase flow, as opposed to applicant's method and apparatus which determines three phase flow characteristics. This patent uses a temperature log and a spinner flowmeter, instead of measuring fluid density, as applicant does.
U.S. Pat. No. 5,047,632, issued to Hunt, discloses the use of a radioactive tracer to characterize multiphase flow in wells. The present invention does not require tracer injection to determine phase velocity. Instead, applicant determines three phase holdup fractions to determine phase velocity, using a gradiomanometer and a densitometer.
U.S. Pat. No. 4,433,573, issued to Hulin, teaches a method of determining two phase flow rates using a vortex meter and a differential pressure transducer. The present invention measures three phase flow rates and does not require the formation of eddies or vortices.
U.S. Pat. No. 4,856,344, issued to Hunt, discloses the use of a gradiomanometer and a venturi meter to measure two phase flow rate. There is no suggestion of even the need to determine three phase flow characteristics.
U.S. Pat. No. 5,033,288, issued to Castel, teaches a method and device for analyzing a multiphase fluid flowing in a pipe, whereby the fluid is tapped off into a pump and decanted to separate the phases. The respective volumes are determined, and the fluid phases are then analyzed. There is no discussion of the use of a gradiomanometer or a densitometer, or even how the method could work in a wellbore. None of the prior work describes a method for determining three phase holdup fractions of fluids flowing in a wellbore, using a relatively inexpensive and simple device. There is therefore still a need for an improved, accurate technique to determine these holdup fractions.